A third party, independent reserve report was done as of June 30, 2013 by DeGolyer & MacNaughton. The year-end 2013 reserve report was completed by Dune. The prices used at year-end 2013 were $93.39 per Bbl and $3.66 per Mmbtu.

Year-End 2012 vs. Year-End 2013

The following table compares proved, probable and possible reserve amounts for year-end 2012 and year-end 2013.

MMboe

MMboe

Reserve Category

Year-End 2012

Year-End 2013

Increase

Proved Developed (PDP, PDNP)

8.4

8.2

(2%)

Proved Undeveloped (PUD)

6.6

7.3

11%

Total Proved

15.0

15.5

3%

Probable/Possible

4.9

13.3

171%

Grand Total

19.9

28.8

94%

The following table compares year-end 2011 reserves with year-end 2013 reserves. Dune underwent a complete financial restructuring at year-end 2011 and the table below reflects activity since the restructuring.

MMboe

MMboe

Reserve Category

Year-End 2011

Year-End 2013

Increase

Proved Developed (PDP, PDNP)

8.6

8.2

(5%)

Proved Undeveloped (PUD)

4.6

7.3

59%

Total Proved

13.2

15.5

17%

Probable/Possible

1.7

13.3

682%

Grand Total

14.9

28.8

93%

As seen below, from year-end 2011 through year-end 2013, we have invested $77.5 million of new capital (excluding ARO), produced 1.63 MMboe, and added 3.91 MMboe, which resulted in a Finding and Development Cost of $19.81/Boe. Production Replacement was 240% during this 24 month period. Year-end 2013 financial and reserve information has not yet been audited.

Reserve Reconciliation

MMboe

Year-End 2011 Proved Reserves

13.24

24 Months Production

<1.63>

Additions/Revisions

3.91

Year-End 2013 Proved Reserves

15.52

Investment (MM$)

77.46

Finding and Development Cost $/Boe

19.81

Listed below is the distribution of reserves by major field.

Major Field Breakout by Reserves Year-End 2013 (MMboe)

Field

Proved

Probable/Possible

Total

Leeville

5.7

12.4

18.2

Garden Island Bay

1.7

.06

2.3

Bateman Lake

1.6

.02

1.8

Chocolate Bayou

0.7

0.0

0.7

Other

5.8

0.1

5.8

Total

15.5

13.4

28.8

2013/2014 Production Volumes

In total, 2013 production was 436 Mbo and 1,913 MMcfe or 755 MBoe. On a daily basis this averaged 2,068 Boe/day and 58% of the production was oil. Production for the 1st quarter of 2013 averaged 1,801 Boe/day reflecting the company having just commenced a drilling program at our Leeville field. Second quarter production averaged 2,606 Boe/day primarily driven by production increases at our Leeville field. June production peaked at 2,733 Boe/day. Third and fourth quarter production averaged 2,047 Boe/day and 1,817 Boe/day respectively. Production at Leeville, our largest producing field, was negatively impacted by a non-operated pipeline shut in of approximately 60 days. Additionally, the field operator at the Leeville field changed on October 1, 2013, and during the transition time from the old to the new operator production declined due to minimal field maintenance activity. Normal field maintenance was resumed in December along with the initiation of another shallow drilling program. Dune completed drilling the Wieting #31 in the Chocolate Bayou field in the 3rd quarter and commenced production as previously reported. The reservoir encountered in this wellbore was very limited and the zone watered out by the end of the 4th quarter. It is anticipated that the well will be sidetracked in 2014 to encounter the full reservoir which is included in our year-end reserve report as a PUD location. Normal declines occurred in our other fields during the third and fourth quarters.

With new drilling activity in our Leeville field coming on production during the first quarter of 2014 we anticipate first quarter production to be between 1,900 and 2,200 Boe/day. Depending on capital availability during the quarter we have several additional drilling and workover opportunities ready to commence in our other fields. January field level production averaged approximately 1,900 Boe/day with 35% of this coming from the Leeville field.

Upside Potential

Over and above the 15.5 MMBoe of proved reserves, the company has identified and additional unrisked 51 MMboe of probable, possible, and exploratory reserves. These projects are defined with recent fully processed 3-D seismic data and within our acreage positions. The majority of this upside potential is within our Garden Island Bay field. Capital required to explore and develop these opportunities is significantly above our current cash flows. During 2014 we anticipate seeking joint venture partners or outside capital to allow the company to participate in drilling these identified upside opportunities.

2014 Budget

The Company is in the process of developing a risk-adjusted budget that will fund some exploratory projects in our Garden Island Bay field in addition to a second development drilling program at our Leeville Field. In addition, we anticipate redrilling, to approximately 20,200 feet, the deep exploratory well in the Leeville field that was junked and abandoned last year. Insurance proceeds will cover substantially all of our cost of drilling this well back to approximately 19,000 feet where the prior well was lost. This risked capital budget will be adapted to the constraints of our available capital, which currently is limited to free cash flow and availability under our revolver. The revolver availability is currently $47.5 million with $29 million drawn and $2 million of standby letters of credit issued. However, actual availability is not based solely on the undrawn/unused portion of the revolver. Borrowing capacity is further limited by the quarterly Debt/EBITDAX of less than 5.0 to 1.0 for year end 2013 and the first quarter of 2014. The Debt/EBITDAX covenant will be 4.0 to 1.0 commencing at the end of the second quarter and going forward in 2014.

James A. Watt, President and CEO of the company stated, "Post the restructuring late in 2011, we have increased reserves and defined significant upside opportunities. The potential for organic growth far exceeds our current cash flow and availability under our revolver. We will continue to carefully monitor our capital program to achieve maximum production from our asset base while staying within the constraints of our credit agreements. We will evaluate potential transactions that can enhance our balance sheet, and allow for the capital investments necessary to develop the opportunities within our asset base."

FORWARD-LOOKING STATEMENTS: This document includes forward-looking statements. Forward-looking statements include, but are not limited to, statements concerning estimates of expected drilling and development wells and associated costs, statements relating to estimates of, and increases in, production, cash flows and values, statements relating to the continued advancement of Dune Energy, Inc.'s projects and other statements which are not historical facts. When used in this document, the words such as "could," "plan," "estimate," "expect," "intend," "may," "potential," "should," and similar expressions are forward-looking statements. Although Dune Energy, Inc. believes that its expectations reflected in these forward-looking statements are reasonable, such statements involve risks and uncertainties and no assurance can be given that actual results will be consistent with these forward-looking statements. Important factors that could cause actual results to differ from these forward-looking statements include the potential that the Company's projects will experience technological and mechanical problems, geological conditions in the reservoir may not result in commercial levels of oil and gas production, changes in product prices and other risks disclosed in Dune's Annual report on Form 10-K filed with the U.S. Securities and Exchange Commission.